Techno-economic analysis of natural gas combined cycles with post-combustion CO2 absorption, including a detailed evaluation of the development potential

We performed a detailed analysis of the potential future costs and performance of post-combustion CO₂ absorption in combination with a natural gas combined cycle (NGCC). After researching state-of-the-art technology, an Excel model was created to analyze possible developments in the performance of energy conversion, CO₂ capture, and CO₂ compression. The input variables for the three time frames we used were based on literature data, product information, expert opinions, and our own analysis. Using a natural gas price of 4.7 €/GJ, we calculated a potential decrease in the costs of electricity from 5.6 €ct/kWh in the short term to 4.8 €ct/kWh in the medium term and 4.5 €ct/kWh in the long term. The efficiency penalty is calculated to decline from 7.9%-points LHV in the short term to 4.9%-points and 3.7%-points in the medium and long terms, respectively. In combination with NGCC improvements, this may cause an improvement in the net efficiency, including CO₂ capture, from 49% in the short term to 55% and 58% in the medium and long terms, respectively. The total capital costs including capital costs of the NGCC ware calculated to decline from 880 in the short term to 750 and 690 €/kW in the medium and long terms, respectively, with a decline in the incremental capital costs due to capture from 350 in the short term to 270 and 240 €/kW in the medium and long terms, respectively. Finally, the avoidance costs may decline from 45 €/tCO₂ in the short term to 33 €/tCO₂ in the medium term and 28 €/tCO₂ in the long term.     

CO2 storage capacity estimation: Methodology and gaps

Implementation of CO₂ capture and geological storage (CCGS) technology at the scale needed to achieve a significant and meaningful reduction in CO₂ emissions requires knowledge of the available CO₂ storage capacity. CO₂ storage capacity assessments may be conducted at various scales—in decreasing order of size and increasing order of resolution: country, basin, regional, local and site-specific. Estimation of the CO₂ storage capacity in depleted oil and gas reservoirs is straightforward and is based on recoverable reserves, reservoir properties and in situ CO₂ characteristics. In the case of CO₂-EOR, the CO₂ storage capacity can be roughly evaluated on the basis of worldwide field experience or more accurately through numerical simulations. Determination of the theoretical CO₂ storage capacity in coal beds is based on coal thickness and CO₂ adsorption isotherms, and recovery and completion factors. Evaluation of the CO₂ storage capacity in deep saline aquifers is very complex because four trapping mechanisms that act at different rates are involved and, at times, all mechanisms may be operating simultaneously. The level of detail and resolution required in the data make reliable and accurate estimation of CO₂ storage capacity in deep saline aquifers practical only at the local and site-specific scales. This paper follows a previous one on issues and development of standards for CO₂ storage capacity estimation, and provides a clear set of definitions and methodologies for the assessment of CO₂ storage capacity in geological media. Notwithstanding the defined methodologies suggested for estimating CO₂ storage capacity, major challenges lie ahead because of lack of data, particularly for coal beds and deep saline aquifers, lack of knowledge about the coefficients that reduce storage capacity from theoretical to effective and to practical, and lack of knowledge about the interplay between various trapping mechanisms at work in deep saline aquifers.     

Intermediate storage of carbon dioxide in geological formations: A technical perspective

Enhanced oil recovery (EOR) through CO₂ flooding has been practiced on a commercial basis for the last 35 years and continues today at several sites, currently injecting in total over 30 million tons of CO₂ annually. This practice is currently exclusively for economic gain, but can potentially contribute to the reduction of emissions of greenhouse gases provided it is implemented on a large scale. Optimal operations in distributing CO₂ to CO₂-EOR or enhanced gas recovery (EGR) projects (referred to here collectively as CO₂-EHR) on a large scale and long time span imply that intermediate storage of CO₂ in geological formations may be a key component. Intermediate storage is defined as the storage of CO₂ in geological media for a limited time span such that the CO₂ can be sufficiently reproduced for later use in CO₂-EHR. This paper investigates the technical aspects, key individual parameters and possibilities of intermediate storage of CO₂ in geological formations aiming at large scale implementation of carbon dioxide capture and storage (CCS) for deep emission reduction. The main parameters are thus the depth of injection and density, CO₂ flow and transport processes, storage mechanisms, reservoir heterogeneity, the presence of impurities, the type of the reservoirs and the duration of intermediate storage. Structural traps with no flow of formation water combined with proper injection planning such as gas-phase injection favour intermediate storage in deep saline aquifers. In depleted oil and gas fields, high permeability, homogeneous reservoirs with structural traps (e.g. anticlinal structures) are good candidates for intermediate CO₂ storage. Intuitively, depleted natural gas reservoirs can be potential candidates for intermediate storage of carbon dioxide due to similarity in storage characteristics.     

Screening CO2 storage options in The Netherlands

This paper describes the development and application of a methodology to screen and rank Dutch reservoirs suitable for long-term large scale CO₂ storage. The screening focuses on off- and on-shore individual aquifers, gas and oil fields. In total 176 storage reservoirs have been taken into consideration: 138 gas fields, 4 oil fields and 34 aquifers, with a total theoretical storage potential of about 3200 Mt CO₂. The reservoirs are screened according to three criteria: potential storage capacity, storage costs and effort needed to manage risk. Due to the large number of reservoirs, which limits the possibility to use any pair-wise comparison method (e.g. Multi-Criteria programs such as Bosda or Naiade), a spreadsheet tool was designed to provide an assessment of each of the criteria through an evaluation of the fields present in the database and a set of scores provided by a (inter)national panel of experts. The assessment is sufficiently simple and allows others to review it, re-do it or expand it. The results of the methodology show that plausible comparisons of prospective sites with limited characterization data are possible.     

Geological storage of CO2 in saline aquifers—A review of the experience from existing storage operations

The experience from CO₂ injection at pilot projects (Frio, Ketzin, Nagaoka, US Regional Partnerships) and existing commercial operations (Sleipner, Snøhvit, In Salah, acid-gas injection) demonstrates that CO₂ geological storage in saline aquifers is technologically feasible. Monitoring and verification technologies have been tested and demonstrated to detect and track the CO₂ plume in different subsurface geological environments. By the end of 2008, approximately 20 Mt of CO₂ had been successfully injected into saline aquifers by existing operations. Currently, the highest injection rate and total storage volume for a single storage operation are approximately 1 Mt CO₂/year and 25 Mt, respectively. If carbon capture and storage (CCS) is to be an effective option for decreasing greenhouse gas emissions, commercial-scale storage operations will require orders of magnitude larger storage capacity than accessed by the existing sites. As a result, new demonstration projects will need to develop and test injection strategies that consider multiple injection wells and the optimisation of the usage of storage space. To accelerate large-scale CCS deployment, demonstration projects should be selected that can be readily employed for commercial use; i.e. projects that fully integrate the capture, transport and storage processes at an industrial emissions source.     

An engineering-economic model of pipeline transport of CO2 with application to carbon capture and storage

Carbon dioxide capture and storage (CCS) involves the capture of CO₂ at a large industrial facility, such as a power plant, and its transport to a geological (or other) storage site where CO₂ is sequestered. Previous work has identified pipeline transport of liquid CO₂ as the most economical method of transport for large volumes of CO₂. However, there is little published work on the economics of CO₂ pipeline transport. The objective of this paper is to estimate total cost and the cost per tonne of transporting varying amounts of CO₂ over a range of distances for different regions of the continental United States. An engineering-economic model of pipeline CO₂ transport is developed for this purpose. The model incorporates a probabilistic analysis capability that can be used to quantify the sensitivity of transport cost to variability and uncertainty in the model input parameters. The results of a case study show a pipeline cost of US$ 1.16 per tonne of CO₂ transported for a 100 km pipeline constructed in the Midwest handling 5 million tonnes of CO₂ per year (the approximate output of an 800 MW coal-fired power plant with carbon capture). For the same set of assumptions, the cost of transport is US$ 0.39 per tonne lower in the Central US and US$ 0.20 per tonne higher in the Northeast US. Costs are sensitive to the design capacity of the pipeline and the pipeline length. For example, decreasing the design capacity of the Midwest US pipeline to 2 million tonnes per year increases the cost to US$ 2.23 per tonne of CO₂ for a 100 km pipeline, and US$ 4.06 per tonne CO₂ for a 200 km pipeline. An illustrative probabilistic analysis assigns uncertainty distributions to the pipeline capacity factor, pipeline inlet pressure, capital recovery factor, annual O&M cost, and escalation factors for capital cost components. The result indicates a 90% probability that the cost per tonne of CO₂ is between US$ 1.03 and US$ 2.63 per tonne of CO₂ transported in the Midwest US. In this case, the transport cost is shown to be most sensitive to the pipeline capacity factor and the capital recovery factor. The analytical model elaborated in this paper can be used to estimate pipeline costs for a broad range of potential CCS projects. It can also be used in conjunction with models producing more detailed estimates for specific projects, which requires substantially more information on site-specific factors affecting pipeline routing.     

Assessing the economic feasibility of regional deep saline aquifer CO2 injection and storage: A geomechanics-based workflow applied to the Rose Run sandstone in Eastern Ohio, USA

Typical top-down regional assessments of CO₂ storage feasibility are sufficient for determining the maximum volumetric capacity of deep saline aquifers. However, they do not reflect the regional economic feasibility of storage. This is controlled, in part, by the number and type of injection wells that are necessary to achieve regional CO₂ storage goals. In contrast, the geomechanics-based assessment workflow that we present in this paper follows a bottom-up approach for evaluating regional deep saline aquifer CO₂ storage feasibility. The CO₂ storage capacity of an aquifer is a function of its porous volume as well as its CO₂ injectivity. For a saline aquifer to be considered feasible in this assessment it must be able to store a specified amount of CO₂ at a reasonable cost per ton of CO₂. The proposed assessment workflow has seven steps that include (1) defining the storage project and goals, (2) characterizing the geology and developing a geomechanical model of the aquifer, (3) constructing 3D aquifer models, (4) simulating CO₂ injection, (5,6) evaluating CO₂ injection and storage feasibility (with and without injection well stimulation), and (7) determining whether it is economically feasible to proceed with the storage project. The workflow was applied to a case study of the Rose Run sandstone aquifer in the Eastern Ohio River Valley, USA. We found that it is feasible in this region to inject 113 Mt CO₂/year for 30 years at an associated well cost of less than US $1.31/t CO₂, but only if injectivity enhancement techniques such as hydraulic fracturing and injection induced micro-seismicity are implemented.     

A method for quick assessment of CO2 storage capacity in closed and semi-closed saline formations

Saline aquifers of high permeability bounded by overlying/underlying seals may be surrounded laterally by low-permeability zones, possibly caused by natural heterogeneity and/or faulting. Carbon dioxide (CO₂) injection into and storage in such “closed” systems with impervious seals, or “semi-closed” systems with non-ideal (low permeability) seals, is different from that in “open” systems, from which the displaced brine can easily escape laterally. In closed or semi-closed systems, the pressure buildup caused by continuous industrial-scale CO₂ injection may have a limiting effect on CO₂ storage capacity, because geomechanical damage caused by overpressure needs to be avoided. In this research, a simple analytical method was developed for the quick assessment of the CO₂ storage capacity in such closed and semi-closed systems. This quick-assessment method is based on the fact that native brine (of an equivalent volume) displaced by the cumulative injected CO₂ occupies additional pore volume within the storage formation and the seals, provided by pore and brine compressibility in response to pressure buildup. With non-ideal seals, brine may also leak through the seals into overlying/underlying formations. The quick-assessment method calculates these brine displacement contributions in response to an estimated average pressure buildup in the storage reservoir. The CO₂ storage capacity and the transient domain-averaged pressure buildup estimated through the quick-assessment method were compared with the “true” values obtained using detailed numerical simulations of CO₂ and brine transport in a two-dimensional radial system. The good agreement indicates that the proposed method can produce reasonable approximations for storage–formation–seal systems of various geometric and hydrogeological properties.     

Pipeline design for a least-cost router application for CO2 transport in the CO2 sequestration cycle

CO₂ capture and geological storage (CCS) is considered as a viable option to mitigate greenhouse gas emissions during the transition phase towards the use of clean and renewable energy. This paper concentrates on the transport of CO₂ between source (CO₂ capture at plants) and sink (geological storage reservoirs). In the cost estimation of CO₂ transport, the pipeline diameter plays an important role. In this respect, the paper reviews equations that were used in several reports on CO₂ pipeline transport. As some parameters are not taken into account in these equations, alternative formulas are proposed which calculate the proper inner diameter size based on flow rate, pressure drop per unit length, CO₂ density, CO₂ viscosity, pipeline material roughness and topographic height differences (the Darcy–Weisbach solution) and, in addition, on the amount and type of bends (the Manning solution). Comparison between calculated diameters using the reviewed and the proposed equations demonstrate the important influence of elevation difference (which is not considered in the reviewed equations) and pipeline material roughness-related factor on the calculated diameter. Concerning the latter, it is suggested that a Darcy–Weisbach roughness height of 0.045 mm better corresponds to a Manning factor of 0.009 than higher Manning values previously proposed in literature. Comparison with the actual diameter of the Weyburn pipeline confirms the accuracy of the proposed equations. Comparison with other existing CO₂ pipelines (without pressure information) indicate that the pipelines are designed for lower pressure gradients than 25 Pa/m or for (future) higher flow rates. The proposed Manning equation is implemented in an economic least-cost route planner in order to obtain the best economic solution for pipeline trajectory and corresponding diameter.     

Investigations on CO2 storage capacity in saline aquifers—Part 2: Estimation of storage capacity coefficients

Many studies on geological carbon dioxide (CO₂) storage capacity neglect the influence of complex coupled processes which occur during and after the injection of CO₂. Storage capacity is often overestimated since parts of the reservoirs cannot be reached by the CO₂ plume due to gravity segregation and are thus not accessible for storage. This work investigates the effect of reservoir parameters like depth, temperature, absolute and relative permeability, and capillary pressure on the processes during CO₂ injection and thus on estimates of effective storage capacity. The applied statistical characteristics of parameters are based on a large reservoir parameter database. Different measured relative permeability relations are considered. The methodology of estimating storage capacity is discussed. Using numerical 1D and 3D experiments, detailed time-dependent storage capacity estimates are derived. With respect to the concept developed in this work, it is possible to estimate effective CO₂ storage capacity in saline aquifers. It is shown that effective CO₂ mass stored in the reservoir varies by a factor of 20 for the reservoir setups considered. A high influence of the relative permeability relation on storage capacity is shown.     

Scenario simulations of CO2 injection feasibility, plume migration and storage in a saline aquifer, Scania, Sweden

Deep saline aquifers have large capacity for geological CO₂ storage, but are generally not as well characterized as petroleum reservoirs. We here aim at quantifying effects of uncertain hydraulic parameters and uncertain stratigraphy on CO₂ injectivity and migration, and provide a first feasibility study of pilot-scale CO₂ injection into a multilayered saline aquifer system in southwest Scania, Sweden. Four main scenarios are developed, corresponding to different possible interpretations of available site data. Simulation results show that, on the one hand, stratigraphic uncertainty (presence/absence of a thin mudstone/claystone layer above the target storage formation) leads to large differences in predicted CO₂ storage in the target formation at the end of the test (ranging between 11% and 98% of injected CO₂ remaining), whereas other parameter uncertainty (in formation and cap rock permeabilities) has small impact. On the other hand, the latter has large impact on predicted injectivity, on which stratigraphic uncertainty has small impact. Salt precipitation at the border of the target storage formation affects CO₂ injectivity for all considered scenarios and injection rates. At low injection rates, salt is deposited also within the formation, considerably reducing its availability for CO₂ storage.     

Numerical investigation concerning the impact of CO2 geologic storage on regional groundwater flow

Large-scale storage of carbon dioxide in saline aquifers may cause considerable pressure perturbation and brine migration in deep rock formations, which may have a significant influence on the regional groundwater system. With the help of parallel computing techniques, we conducted a comprehensive, large-scale numerical simulation of CO₂ geologic storage that predicts not only CO₂ migration, but also its impact on regional groundwater flow. As a case study, a hypothetical industrial-scale CO₂ injection in Tokyo Bay, which is surrounded by the most heavily industrialized area in Japan, was considered, and the impact of CO₂ injection on near-surface aquifers was investigated, assuming relatively high seal-layer permeability (higher than 10 microdarcy). A regional hydrogeological model with an area of about 60 km × 70 km around Tokyo Bay was discretized into about 10 million gridblocks. To solve the high-resolution model efficiently, we used a parallelized multiphase flow simulator TOUGH2-MP/ECO2N on a world-class high performance supercomputer in Japan, the Earth Simulator. In this simulation, CO₂ was injected into a storage aquifer at about 1 km depth under Tokyo Bay from 10 wells, at a total rate of 10 million tons/year for 100 years. Through the model, we can examine regional groundwater pressure buildup and groundwater migration to the land surface. The results suggest that even if containment of CO₂ plume is ensured, pressure buildup on the order of a few bars can occur in the shallow confined aquifers over extensive regions, including urban inlands.     

Water/acid gas interfacial tensions and their impact on acid gas geological storage

Acid gas geological disposal is a promising process to reduce CO₂ atmospheric emissions and an environment-friendly and economic alternative to the transformation of H₂S into sulphur by the Claus process. Acid gas confinement in geological formations is to a large extent controlled by the capillary properties of the water/acid–gas/caprock system, because a significant fraction of the injected gas rises buoyantly and accumulates beneath the caprock. These properties include the water/acid gas interfacial tension (IFT), to which the so-called capillary entry pressure of the gas in the water-saturated caprock is proportional. In this paper we present the first ever systematic water/acid gas IFT measurements carried out by the pendant drop technique under geological storage conditions. We performed IFT measurements for water/H₂S systems over a large range of pressure (up to P = 15 MPa) and temperature (up to T = 120 °C). Water/H₂S IFT decreases with increasing P and levels off at around 9–10 mN/m at high T (≥70 °C) and P (>12 MPa). The latter values are around 30–40% of water/CO₂ IFTs, and around 20% of water/CH₄ IFTs at similar T and P conditions. The IFT between water and a CO₂ + H₂S mixture at T = 77 °C and P > 7.5 MPa is observed to be approximately equal to the molar average IFT of the water/CO₂ and water/H₂S binary mixtures. Thus, when the H₂S content in the stored acid gas increases the capillary entry pressure decreases, together with the maximum height of acid gas column and potential storage capacity of a given geological formation. Hence, considerable attention should be exercised when refilling with a H₂S-rich acid gas a depleted gas reservoir, or a depleted oil reservoir with a gas cap: in the case of hydrocarbon reservoirs that were initially (i.e., at the time of their discovery) close to capillary leakage, acid gas leakage through the caprock will inevitably occur if the refilling pressure approaches the initial reservoir pressure.     

Techno-Economic Study of CO2 Capture from an Existing Cement Plant Using MEA Scrubbing

Carbon dioxide is the major greenhouse gas responsible for global warming. Man-made CO₂ emissions contribute approximately 63% of greenhouse gases and the cement industry is responsible for approximately 5% of CO₂ emissions emitting nearly 900 kg of CO₂ per 1000 kg of cement. CO₂ from a cement plant was captured and purified to 98% using the monoethanolamine (MEA) based absorption process. The capture cost was $51 per tonne of CO₂ captured, representing approximately 90% of total cost. Steam was the main operating cost representing 39% of the total capture cost. Switching from coal to natural gas reduces CO₂ emissions by about 18%. At normal load, about 36 MW of waste heat is available for recovery to satisfy the parasitic heat requirements of MEA process; however, it is very difficult to recover.     

Life cycle assessment of a pulverized coal power plant with post-combustion capture, transport and storage of CO2

In this study the methodology of life cycle assessment has been used to assess the environmental impacts of three pulverized coal fired electricity supply chains with and without carbon capture and storage (CCS) on a cradle to grave basis. The chain with CCS comprises post-combustion CO₂ capture with monoethanolamine, compression, transport by pipeline and storage in a geological reservoir. The two reference chains represent sub-critical and state-of-the-art ultra supercritical pulverized coal fired electricity generation. For the three chains we have constructed a detailed greenhouse gas (GHG) balance, and disclosed environmental trade-offs and co-benefits due to CO₂ capture, transport and storage. Results show that, due to CCS, the GHG emissions per kWh are reduced substantially to 243 g/kWh. This is a reduction of 78 and 71% compared to the sub-critical and state-of-the-art power plant, respectively. The removal of CO₂ is partially offset by increased GHG emissions in up- and downstream processes, to a small extent (0.7 g/kWh) caused by the CCS infrastructure. An environmental co-benefit is expected following from the deeper reduction of hydrogen fluoride and hydrogen chloride emissions. Most notable environmental trade-offs are the increase in human toxicity, ozone layer depletion and fresh water ecotoxicity potential for which the CCS chain is outperformed by both other chains. The state-of-the-art power plant without CCS also shows a better score for the eutrophication, acidification and photochemical oxidation potential despite the deeper reduction of SO_x and NO_x in the CCS power plant. These reductions are offset by increased emissions in the life cycle due to the energy penalty and a factor five increase in NH₃ emissions.     

Integration of counter-current relative permeability in the simulation of CO2 injection into saline aquifers

Carbon dioxide (CO₂) injection into saline aquifers is one of the promising options to sequester large amounts of CO₂ in geological formations. During as well as after injection of CO₂ into an aquifer, CO₂ migrates towards the top of the formation due to density differences between the formation brine and the injected CO₂. The time scales of CO₂ migration towards the top of an aquifer and the fraction of CO₂ that is trapped as residual gas depends strongly on the driving forces that are acting on the injected CO₂.When CO₂ migrates to the top of an aquifer, brine may be displaced downwards in a counter-current flow setting particularly during the injection period. A majority of the published work on counter-current flow settings have reported significant reductions in the associated relative permeability functions as compared to co-current measurements. However, this phenomenon has not yet been considered in the simulation of CO₂ storage into saline aquifers.In this paper we study the impact of changes in mobility for the two-phase brine/CO₂ system as a result of transitions between co- and counter-current flow settings. We have included this effect in a simulator and studied the impact of the related mobility reduction on the saturation distribution and residual saturation of CO₂ in aquifers over relevant time scales. We demonstrate that the reduction in relative permeability in the vertical direction changes the plume migration pattern and has an impact on the amount of gas that is trapped as a function of time. This is to our best knowledge the first attempt to integrate counter-current relative permeability into the simulation of injection and subsequent migration of CO₂ in aquifers. The results and analysis presented in this paper are directly relevant to all ongoing activities related to the design of large-scale CO₂ storage in saline aquifers.     

CO2 transportation for carbon capture and storage: Sublimation of carbon dioxide from a dry ice bank

Climate change is being caused by greenhouse gases such as carbon dioxide (CO₂). Carbon capture and storage (CCS) is of interest to the scientific community as one way of achieving significant global reductions of atmospheric CO₂ emissions in the medium term. CO₂ would be captured from large stationary sources such as power plants and transported via pipelines under high pressure conditions to underground storage. If a downward leakage from a surface transportation system module occurs, the CO₂ would undergo a large temperature reduction and form a bank of “dry ice” on the ground surface; the sublimation of the gas from this bank represents an area source term for subsequent atmospheric dispersion, with an emission rate dependent on the energy balance at the bank surface. Gaseous CO₂ is denser than air and tends to remain close to the surface; it is an asphyxiant, a cerebral vasodilator and at high concentrations causes rapid circulatory insufficiency leading to coma and death. Hence a subliming bank of dry ice represents safety hazard. A model is presented for evaluating the energy balance and sublimation rate at the surface of a solid frozen CO₂ bank under different environmental conditions. The results suggest that subliming gas behaves as a proper dense gas (i.e. it remains close to the ground surface) only for low ambient wind speeds.     

Capture-ready coal plants—Options,technologies and economics

This paper summarizes the spectrum of options that can be employed during the initial design and construction of pulverized coal (PC), and integrated gasification and combined cycle (IGCC) plants to reduce the capital costs and energy losses associated with retrofitting for CO₂ capture at some later time in the future. It also estimates lifetime (40 year) net present value (NPV) costs of plants with differing levels of pre-investment for CO₂ capture under a wide range of CO₂ price scenarios. Three scenarios are evaluated—a baseline supercritical PC plant, a baseline IGCC plant and an IGCC plant with pre-investment for capture. This analysis evaluates each technology option under a range of CO₂ price scenarios and determines the optimum year of retrofit, if any. The results of the analysis show that a baseline PC plant is the most economical choice under low CO₂ prices, and IGCC plants are preferable at higher CO₂ prices (e.g., an initial price of about $22/t CO₂ starting in 2015 and growing at 2%/year). Little difference is seen in the lifetime NPV costs between the IGCC plants with and without pre-investment for CO₂ capture. This paper also examines the impact of technology choice on lifetime CO₂ emissions. The difference in lifetime emissions become significant only under mid-estimate CO₂ price scenarios (roughly between $20 and 40/t CO₂) where IGCC plants will retrofit sooner than a PC plant.     

An experimental and numerical investigation into the impact of dissolution/precipitation mechanisms on CO2 injectivity in the wellbore and far field regions

Carbon dioxide capture and storage (CCS) technology is gaining credibility as the best short to medium term solution for significantly reducing net carbon emissions into the atmosphere. From a capacity point of view, deep saline aquifers offer the greatest potential for CO₂ storage. In this respect, well injectivity is considered a key technical and economical issue. Rock/fluid interactions – dissolution/precipitation of minerals, in particular carbonates – are currently considered as one of the principal reasons for wellbore injectivity changes in aquifers.This research investigated the mechanisms involved in injectivity losses through experimental and theoretical methods. The impact on injectivity of permeability changes occurring at various distances from the wellbore was studied using an idealised CO₂ injection well flow model. A new experimental set-up was used to investigate the effect on dissolution/precipitation mechanisms of the pressure and temperature changes that the fluid is subjected to as it advances from the wellbore.Numerical modelling of the injection wellbore has shown that changes in the petrophysical properties of the reservoir several metres away from the wellbore can still have a significant impact on injectivity. As indicated by the experimental research carried out, pressure and temperature gradients that exist inside the reservoirs may lead to re-precipitation in the far field, however no significant permeability and porosity changes were detected to suggest major losses of injectivity due to these effects.     

Life cycle modelling of fossil fuel power generation with post-combustion CO2 capture

Due to its compatibility with the current energy infrastructures and the potential to reduce CO₂ emissions significantly, CO₂ capture and geological storage is recognised as one of the main options in the portfolio of greenhouse gas mitigation technologies being developed worldwide. The CO₂ capture technologies offer a number of alternatives, which involve different energy consumption rates and subsequent environmental impacts. While the main objective of this technology is to minimise the atmospheric greenhouse gas emissions, it is also important to ensure that CO₂ capture and storage does not aggravate other environmental concerns. This requires a holistic and system-wide environmental assessment rather than focusing on the greenhouse gases only. Life Cycle Assessment meets this criteria as it not only tracks energy and non-energy-related greenhouse gas releases but also tracks various other environmental releases, such as solid wastes, toxic substances and common air pollutants, as well as the consumption of other resources, such as water, minerals and land use. This paper presents the principles of the CO₂ capture and storage LCA model developed at Imperial College and uses the pulverised coal post-combustion capture example to demonstrate the methodology in detail. At first, the LCA models developed for the coal combustion system and the chemical absorption CO₂ capture system are presented together with examples of relevant model applications. Next, the two models are applied to a plant with post-combustion CO₂ capture, in order to compare the life cycle environmental performance of systems with and without CO₂ capture. The LCA results for the alternative post-combustion CO₂ capture methods (including MEA, K⁺/PZ, and KS-1) have shown that, compared to plants without capture, the alternative CO₂ capture methods can achieve approximately 80% reduction in global warming potential without a significant increase in other life cycle impact categories. The results have also shown that, of all the solvent options modelled, KS-1 performed the best in most impact categories.